1. Technical Field
This invention relates to fluid flow sensing devices that use fiber optics and more particularly to those devices that measure the speed of sound, flow velocity, and other parameters within a pipe using acoustic signals and local short duration pressure variations within the flow.
2. Background Information
In the petroleum industry, there is considerable value in the ability to monitor the flow of petroleum products in the production pipe of a well in real time. Historically, flow parameters such as the bulk velocity of a fluid have been sensed with venturi type devices directly disposed within the fluid flow. These type devices have several drawbacks including that they provide an undesirable flow impediment, are subject to the hostile environment within the pipe, and typically provide undesirable potential leak paths into or out of the pipe. In addition, these type devices are also only able to provide information relating to the bulk fluid flow and are therefore unable to provide information specific to constituents within a multi-phase flow.
Some techniques utilize the speed of sound to determine various parameters of the fluid flow within a pipe. One technique measures the amount of time it takes for sound signals to travel back and forth between ultrasonic acoustic transmitters/receivers (transceivers). This is sometimes referred to as a “sing-around” or “transit time” method. U.S. Pat. Nos. 4,080,837, 4,114,439, 5,115,670 disclose variations of this method. A disadvantage of this type of technique is that gas bubbles and/or particulates in the fluid flow can interfere with the signals traveling back and forth between the transceivers. Another disadvantage of this type of technique is that it considers only the fluid disposed between transceivers during the signal transit time. Fluid flow within a well will very often be non-homogeneous, for example containing localized concentration variations (“slugs”) of water or oil. Localized concentration variations can affect the accuracy of the data collected.
Multiphase flow meters can be used to measure the flow rates of individual constituents within a fluid flow (e.g., a mixture of oil, gas, and water) without requiring separation of the constituents. Most of the multiphase flow meters that are currently available, however, are designed for use at the wellhead or platform. A problem with utilizing a flow meter at the wellhead of a multiple source well is that the fluid flow reaching the flow meter is a mixture of the fluids from the various sources disposed at different positions within the well. Thus, although the multiphase meter provides information specific to individual constituents within a fluid flow (which is an improvement over a bulk flow sensors), the information they provide is still limited because there is no way to distinguish sources.
Acquiring reliable, accurate fluid flow data downhole at a particular source environment is a technical challenge for at least the following reasons. First, fluid flow within a production pipe is hostile to sensors in direct contact with the fluid flow, and can cause the sensors to erode, corrode, wear, or otherwise compromise their integrity. In addition, the hole or port in the pipe through which the sensor makes direct contact, or through which a cable is run, is a potential leak site, which is highly undesirable. Second, the environment in most wells is harsh, and is characterized by extreme temperatures, pressures, and debris. Extreme temperatures can disable and limit the life of electronic components. Sensors disposed outside of the production pipe may also be subject to environmental constituents such as water (fresh or salt), steam, mud, sand, etc. Third, the well environment makes it difficult and expensive to access most sensors once they have been installed and positioned downhole.
What is needed, therefore, is a reliable, accurate, and compact apparatus for sensing fluid flow within a pipe that can sense fluid flow within a pipe in a non-intrusive manner over a broad range of conditions, that is operable in an environment characterized by extreme temperatures and pressures and the presence of debris, that can operate remotely, and that is not likely to need replacement or recalibration once installed. Such are the objects of the present disclosure.